Downhole pumping of wellbore fluids is the most frequent method used for secondary recovery of crude oil in petroleum production. Downhole pumping involves procedures and devices through which the pumping energy gets to the wellbore fluids, so that wellbore fluids move up the downhole, to the surface, through production tubing. Devices used for this purpose are amongst the most diverse in the industry, though only few models have made inroads sufficient to become standardized. They are generically known as downhole plunger pumps, PCP (Progressive Cavity Pumps), ESP (Electrical Submersible Pumps), and “screw” pumps.
From a constructive stand point, the devices used for downhole pumping, no matter the pumping option per se, have the following components: a part, the driver, whereby mechanical energy is generated; another part transmitting the mechanical energy previously generated to the pump; and the pump itself. The pump transfers the mechanical energy brought from surface to the wellbore fluids, turning it into pressure of the fluids. In the oil field the electrical motor has become the device of choice in generating mechanical energy to drive the pump, though there are many applications where one may see steam driving, hydraulic or pneumatic driving as alternate options to drive the pump. Mechanical energy from the driver can be delivered to the pump either through sucker rods (in this case the driver being at the surface and the pump downhole), or can be produced and used locally. This second option is so-called “bottom hole driver” or “direct drive”; e.g. PCP pumps driven through bottom hole drivers, “screw” pumps driven through bottom hole drivers or ESP pumps driven in the same way.
In the petroleum industry, the wellbore fluids, the wellbore itself or even the reservoir rock nearby the wellbore, needs conditioning. The purpose of conditioning wellbore fluids is to control scaling (either organic or mineral) inside the production tubing, the casing or to pump, to keep the aggressivity of the wellbore fluids under control (avoid corrosion, for example) or to improve flowing properties of wellbore fluids. In order to condition wellbore fluids a conditioning agent (dilutants, solvents, steam, hot water, specialty chemicals) is added (injected) either continuously or in batches, either into the wellbore or downstream of the wellhead during pumping the well. Adding conditioning agent to the wellbore fluids is presently done through pumping. From the surface the conditioning agent is pumped through an annulus, through an injection line (in which case the injection line is set in the annulus). Pumping of the conditioning agent in the annulus is barely controllable, leading to excessive consumption of conditioning agent and poor control of conditioning. Injecting it downhole, through a separate line means costly supplementary logistics. Both disadvantages have as a starting point the actual configuration of sucker rods used to pump the well.
Conditioning the wellbore or the reservoir rock nearby the wellbore involves pumping the conditioning agents (steam, hot oil, hot water, specialty chemicals) under high pressure (injecting) into the wellbore or the pay zone, thus controlling wellbore integrity or flowing characteristics of the reservoir rock. Today, realizing this goal means that one has to shut down the well, pull out the sucker rod string, condition the wellbore or the formation, set the sucker rods string and the pump back into the well and resume production. Associated to production disruption is the production lost while conditioning the well. This means that one has to invest supplementarily in costly logistics, to do the conditioning, and both, when considered together, increased cost of conditioning as well as overall operational expenses of producing the well. The above-mentioned disadvantages have as a starting point the actual configuration of sucker rods used to pump the well.
For historical reasons, as well as because of infrastructure on site, delivering mechanical energy to PCPs or to screw pumps is done (nowadays) through the same sucker rods strings used for downhole plunger pumps. There is one major difference, though, and that has to be considered while comparing driving PCPs and “screw” pumps to plunger pumps. While transmitting mechanical energy to the pump, the sucker rods used to drive downhole plunger pumps move up and down, axially; the sucker rods used to drive PCPs or “screw” pumps rotate.
The sucker rods used in the oil field are nowadays standardized, all sucker rods manufacturers following API 11B standard (American Petroleum Institute).
Such sucker rod is a continuous full bodied metallic bar, with both e s profiled and threaded to allow end-to-end connection in a sucker rod string. The string thus made is used to transmit mechanical energy from the driver (at surface) to the pump (downhole).
Using full bodied sucker rods strings leads to extra cost, involves supplementary, costly logistics, and special operations and lost production associated with, whenever the wellbore fluids, the weilbore itself or the formation pay zone has to be conditioned, as outlined above.
Another disadvantage of using classical sucker rod/pumping technology is that it renders as expensive and non-attractive live data gathering for parameters like the bottom hole temperature and pressure, flowing properties of the weilbore fluids, or the pumping regime. Bringing the information from bottom hole transducers to the surface, while pumping the well it involves the use of special data cables inserted in the annulus between the production tubing and the production casing, and designed to stand the aggressivity of weilbore fluids, as well as the combined effect of temperature and pressure. For special purpose applications alternatives exist but they involve converting the electric signals from bottom hole transducers into ironic or electromagnetic waves beamed to the surface an option even more expensive and difficult to implement.
One may encounter similar troubles when direct drive applications are considered for PCPs, screw pumps or ESPs where the use of bottom hole electric motors is needed. Bringing the power to the bottom hole electric motors requires power cables usually inserted in the hole through an annulus and designed to stand the aggressivity of wellbore fluids, as well as the combined effect of temperature and pressure. These cables are very expensive and sometimes this renders the bottom hole direct drive technique non-attractive.
Alternative option to driving downhole pumps (no matter whether plunger, PCP, screw or ESP) has been designed and it involves the use of flexible coiled tubing instead of classical sucker rods. This option is more expensive than traditional sucker rods driving and consequently of limited use. To compound the issue, using coiled tubing means that special infrastructure must be available on site. Because of that the cost of replacing the classical sucker rods technology becomes prohibitive.